The invention generally relates to interpreting well test measurements.
An oil and gas well typically is tested for purposes of determining the reservoir productivity and other key properties of the subterranean formation to assist in decision making for field development. The testing of the well provides such information as the formation pressure and its gradient; the average formation permeability and/or mobility; the average reservoir productivity; the permeability/mobility and reservoir productivity values at specific locations in the formation; the formation damage assessment near the wellbore; the existence or absence of a reservoir boundary; and the flow geometry and shape of the reservoir. Additionally, the testing may be used to collect representative fluid samples at one or more locations.
Various testing tools may be used to obtain the information listed above. One such tool is a wireline tester, a tool that withdraws only a small amount of the formation fluid and may be desirable in view of environmental or tool constraints. However, the wireline tester only produces results in a relatively shallow investigation radius; and the small quantity of the produced fluid sometimes is not enough to clean up the mud filtrate near the wellbore, leading to unrepresentative samples being captured in the test.
Due to the limited capability of the wireline tester, testing may be performed using a drill string that receives well fluid. As compared to the wireline tester, the drill string allows a larger quantity of formation fluid to be produced in the test, which, in turn, leads to larger investigation radius, a better quality fluid sample and a more robust permeability estimate. In general, tests that use a drill string may be divided into two categories: 1.) tests that produce formation fluid to the surface (called “drill stem tests” (DSTs)); and 2.) tests that do not flow formation fluid to the surface but rather, flow the formation fluid into an inner chamber of the drill string (called “closed chamber tests” (CCTs), or “surge tests”).
For a conventional DST, production from the formation may continue as long as required since the hydrocarbon that is being produced to the surface is usually flared via a dedicated processing system. The production of this volume of fluid ensures that a clean hydrocarbon is acquired at the surface and allows for a relatively large radius of investigation. Additionally, the permeability calculation that is derived from the DST is also relatively simple and accurate in that the production is usually maintained at a constant rate by means of a wellhead choke. However, while usually providing relatively reliable results, the DST typically has the undesirable characteristic of requiring extensive surface equipment to handle the produced hydrocarbons, which, in many situations, poses an environmental handling hazard and requires additional safety precautions.
In contrast to the DST, the CCT is more environmentally friendly and does not require expensive surface equipment because the well fluid is communicated into an inner chamber (called a “surge chamber”) of the drill string instead of being communicated to the surface of the well. However, due to the downhole confinement of the fluid that is produced in a CCT, a relatively smaller quantity of fluid is produced in a CCT than in a DST. Therefore, the small produced fluid volume in a CCT may lead to less satisfactory wellbore cleanup. Additionally, the mixture of completion, cushion and formation fluids inside the wellbore and the surge chamber may deteriorate the quality of any collected fluid samples. Furthermore, in the initial part of the CCT, a high speed flow of formation fluid (called a “surge flow”) enters the surge chamber. The pressure signal (obtained via a chamber-disposed pressure sensor) that is generated by the surge flow may be quite noisy, thereby affecting the accuracy of the formation parameters that are estimated from the pressure signal.
For reservoirs with weak pressure, the upper end of the surge chamber may be open to production facilities or temporary processing system during the test. This type of test is called “slug test”. When the wellbore liquid column, or the “slug”, reaches the surface, the slug test terminates and a conventional DST starts. A slug test has the similar characteristics of a surge flow as a CCT, so it shares the similar issues in its data interpretation. Many other operations, such under-balanced perforating using a wireline conveyed gun, may also lead to similar issues when analyzing the measured data. The primary feature of these tests is the variation of skin effect factor due to the continuous increase in damage from the injection of incompatible fluids, or, a continuous decrease in skin factor from clean-up. The variation of skin effect factor is often, but not always, compounded with variable flow rate, making the problem more challenging.
The data that is obtained from a CCT, slug test, or other tests with surge flow, may be relatively difficult to interpret due to complicated wellbore dynamics and other effects. Thus, there exists a continuing need for better ways to interpret test results that are obtained from these tests.